Various methods are used in the recovery of deeply buried heavy oil or bitumen deposits within oil-sands reservoirs. In situ heavy oil or bitumen recovery techniques are applied to indigenous resource that cannot be mined economically because of the depth of the overburden. It is recognized that in situ methods disturb considerably less land and therefore require less land-reclamation activity than mining projects. In situ production methods may recover between 25 and 75 percent of the initially present heavy oil or bitumen in a reservoir. In general, the focus of in situ heavy oil or bitumen recovery processes is to reduce the viscosity of the heavy oil or bitumen to enable it to be produced from a well and transported by pipeline or other means.
All existing in situ methods to recover heavy oil or bitumen deposits exploit at least one of temperature, pressure, and/or solvent to reduce bitumen viscosity or otherwise enhance the flow of bitumen within the reservoir.
One in situ recovery method is Steam Assisted Gravity Drainage (SAGD), as described in U.S. Pat. No. 4,344,485 (Butler), which requires two horizontal wells to be drilled into the reservoir. In this method, two spaced apart wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction that result in two horizontal wells, vertically spaced from, but otherwise vertically aligned with the other. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is placed above or nearly above the production well.
The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the horizontal injection well, permeating the reservoir to form a vapor chamber that grows over time towards the reservoir top, thereby increasing the temperature within the reservoir. The steam (and its condensate), by soaking for a period of time, will raise the temperature and consequently reduce the viscosity of the semi-solid bitumen or heavy oil in the reservoir. The bitumen and condensed steam will then drain downward through the reservoir under the action of gravity and flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface of the well, the condensed steam and bitumen are separated, and the bitumen is diluted with appropriate light hydrocarbons to transport the bitumen by pipeline to a refinery or an upgrader.
The theoretical and design concepts required to conduct successful SAGD have been published and have been extensively discussed in technical and related industry literature. A major component of the capital and operating costs of commercial SAGD operations are the facilities to: a) generate steam, b) separate hydrocarbons from condensed steam, and c) treat and recycle water to the steam generators. Current steam generators require large amounts of water, which is heated by boilers fired by natural gas to produce steam. The volume of water handled in SAGD operations is reflected in steam-to-oil ratios (e.g. CWE m3 steam/m3 bitumen) of about 2 and above for active or anticipated projects. While SAGD is effective at producing bitumen from the reservoir to the surface, there continues to be a need for systems that improve the steam-to-oil ratio of SAGD consistent with increases to the thermal efficiency of the process and improvements in the cost efficiency of the process.
A variant of the SAGD process is the Steam and Gas Push (SAGP) process. In SAGP, a non-condensable gas is co-injected with the steam to provide an insulating layer at the top of the vapour chamber. While this results in higher thermal efficiency, the non-condensable gas may add cost and complexity to the process.
The literature provides further examples of enhanced bitumen recovery using steam. For example, U.S. Pat. No. 4,519,454 (McMillen) describes a heavy oil recovery method which comprises heating the surrounding reservoir with steam at a temperature below the coking temperature but sufficient to raise the temperature by 40-200° F. (22-111° C.). Production is then initiated immediately after heating without a soak period. Production continues until steam is produced from the production well, whereafter a liquid solvent is injected into the injection well, such that a solvent and oil mixture will be produced. The process McMillen describes is essentially a cyclic thermal-solvent process alternating between thermal and solvent intervals, and usually requires several phases of costly steam injection.
U.S. Pat. No. 4,697,642 (Vogel) teaches a steam flooding and solvent flooding process in which steam and vapourized solvent are injected into the reservoir in a stepwise condensation process to recover high viscosity hydrocarbons. In this process, the choice of solvent is not considered critical and it is suggested that the solvent is a light and readily distillable liquid that is miscible with the in situ hydrocarbons. Examples include gasoline, kerosene, naphtha, gas well and plant condensates, intermediate refinery streams, benzene, toluene, and distillate and cracked products. The process makes use of a high solvent to hydrocarbon ratio which adversely impacts the economics of the process.
Palmgren (SPE Paper 30294, 1995) describes the use of high temperature naphtha to replace steam in the SAGD process. For the process to be economic and compete with SAGD, significant naphtha recovery at the end of the process is required.
A Vapour Extraction process, called VAPEX, has been proposed as a more environmentally friendly and commercially viable alternative to SAGD. In VAPEX, as in SAGD, two horizontal wells are placed in the reservoir, with the injection well located above the production well. In the VAPEX process steam is not injected, but a gaseous solvent (for example ethane, propane, or butane) is injected into the reservoir through the injection well, where it condenses and mixes with the bitumen to reduce the viscosity of the bitumen. Both bitumen and the dissolved solvent flow downward under gravity to the production well for production to the surface. The capital costs associated with the facilities for VAPEX are much less than that of SAGD because the process does not require steam generation or water treating/handling capability. The VAPEX process, however, is associated with a lengthy start-up interval due to the difficulties associated with growing a vapour chamber without steam. The potential condensation of the gaseous solvent limits the reservoir operating pressures that are permitted to maintain a vapour chamber.
Butler and Mokrys (J. Can. Pet. Tech., 30(1): 97, 1991) initially documented the VAPEX process to recover heavy oil by using hot water and a solvent vapour near its dew point in an experimental Hele-Shaw cell. The solvent dissolves into the heavy oil, reducing its viscosity, which causes it to flow along the chamber edge to the production well located low in the formation. The hydrocarbon solvent, for example propane, continues to fill the expanding chamber. The solvent is co-injected with hot water to raise the reservoir temperature by between 4° and 80° C. The hot water also re-vaporizes some of the solvent from the heavy oil to create refluxing and additional utilization of the solvent. Butler and Mokrys (J. Can. Pet. Tech., 32(6): 56, 1994) disclose further details of the VAPEX process from the results of VAPEX physical model experiments.
U.S. Pat. No. 5,607,016 (Butler) describes a variant of the VAPEX process for use in reservoirs overlying an aquifer. A non-condensable displacement gas is co-injected with a hydrocarbon solvent at sufficient pressure to limit water ingress into the recovery zone.
Das and Butler (J. Can. Pet. Tech., 33(6): 39, 1994) discuss the impact of asphaltene precipitation on the VAPEX process. One concern with previous processes has been the potential plugging of the reservoir pore space by deposited asphaltenes, which would affect the flow of diluted heavy oil to the production well. Das and Butler were able to show that the VAPEX process was not susceptible to asphaltene plugging.
U.S. Pat. No. 5,899,274 (Frauenfeld et al.) teaches a solvent-aided method to mobilize viscous heavy oil by mixing at least two solvents, each soluble in oil, to form a substantially gaseous solvent mixture having a dew point that corresponds with the reservoir temperature and pressure. In this process, there is a reduced need to manipulate the reservoir temperature and pressure to provide conditions which would mobilize and recover oil from the reservoir.
Luhning et al. (CHOA Conference, Calgary, Canada, 1999) discusses the economics of the VAPEX process. Butler and Jiang (J. Can. Pet. Tech., 39(1): 48 2000) describe means to fine-tune VAPEX in the field.
There are many published results of the drainage rates for field conditions in the SAGD process, some examples include: Butler (Thermal Recovery of Oil and Bitumen, Grav-Drain Inc., Calgary, Alberta, 1997), Komery et al. (Paper 1998.214, Seventh UNITAR International Conference, Beijing, China, 1998), Saltuklaroglu et al. (Paper 99-25, CSPG and Petroleum Society Joint Convention, Calgary, Canada, 1999), Butler et al. (J. Can. Pet. Tech., 39(1): 18, 2000).
Canadian Patent No. 1,059,432 (Nenninger) deals with reducing the viscosity of heavy hydrocarbons in oil sand with a pressurized solvent gas such as ethane or carbon dioxide. The solvent gas temperature is maintained below its critical temperature at a pressure between 95% of its saturation pressure and not more than its saturation pressure.
Canadian Patent No. 2,323,029 (Nasr and Isaacs) describes a method (Expanding Solvent-SAGD, ES-SAGD) consisting of injecting steam and an additive into the reservoir. The additive can be one or a combination of C1 to C25 hydrocarbons and carbon dioxide, chosen so that its evaporation temperature is within about ±150° C. of the steam temperature at the operating pressure. After injection into the reservoir, a portion of the additive condenses in the reservoir. The concentration of additive in the steam is in the range from about 0.1% to about 5% liquid volume. The steam injection is continuous and hence the patent does not teach stopping the steam injection.
Canadian Patent No. 2,325,777 (Gutek et al.) describes a Combined Steam and Vapor Extraction Process (SAVEX) to recover hydrocarbons. First, steam is injected into an upper horizontal well until the upper surface of the steam chamber is located approximately 25% to 75% of the distance from the injection well to the top of the reservoir or the recovery rate of hydrocarbons from the reservoir is approximately 25 to 75% of the peak rate predicted for SAGD. Thereafter, a viscosity-reducing solvent is injected that is capable of existing in vapour form in the chamber to mobilize and recover an additional fraction of hydrocarbons.
Canadian Patent Application No. 2,391,721 (Nasr) describes an additional process for recovering hydrocarbons. A heated fluid composition (steam and/or hot water and a solvent) is injected into the formation. Suitable solvents include C1 to C30 hydrocarbons, carbon dioxide; carbon monoxide and associated combinations. The heated injection fluid composition has initially a steam+water-to-solvent volume ratio greater than or about 1. The steam+water-to-solvent volume ratio is subsequently reduced, at least once, to a different steam+water-to-solvent volume ratio which is still greater than or equal to about 1. The injected volume ratio of steam+liquid water-to-solvent is reduced as the process evolves. This process is referred to as Tapered Steam and Solvent-SAGD (TSS-SAGD). The same solvent is used throughout the process, only the ratio of water to solvent is altered as production progresses.
Das et al. (Paper 2004-264, CIPC Conference, Calgary, Canada, 2004) discuss the effect of solvent concentration on bitumen production in ES-SAGD and show through a simulation study that solvent concentrations in the injected stream greater than 15% volume of steam (CWE) give a marginal enhancement of process performance.
Despite the numerous attempts to recover bitumen and heavy oil in situ, as described above, there remains a need for a more cost-effective in situ bitumen extraction method. It is, therefore, desirable to provide a method capable of increasing the quantity of bitumen produced from a reservoir, or demonstrating an ability to remove bitumen more economically than is presently known. Accordingly, this invention satisfies this desire.